The present application relates generally to systems and methods for analysis of produced petroleum, and more particularly to correcting on-line permittivity based analyzer measurements of water content in petroleum.
The following paragraphs contain some discussion, which is illuminated by the innovations disclosed in this application, and any discussion of actual or proposed or possible approaches in this Background section does not imply that those approaches are prior art.
Measurement of the quantity, density, average temperature, and water percentage in petroleum has been an important issue to the petroleum industry. The methods of measurement have been investigated and have undergone continued improvement over the years. Composite samplers are commonly used as the standard by which water content is determined in petroleum as it is being transported in pipelines. A composite sampler is a system that obtains a small sample from a pipeline proportional to time or volume to represent the entire petroleum load. Unfortunately, results for composite samplers are typically only available at the end of a batch, and there is no recourse if something goes wrong with the sampling system during the batch. At the end of the batch only a single number is available to consider. Originally petroleum products contained only a narrow range of densities, and due to this fact composite samplers required testing against one density of oil. Today petroleum products contain a much larger variation in types of crude oils and densities. However, composite samplers are typically validated on one type of product with the assumption that they are valid for all densities and types. Moreover, the exposure of personnel to hazardous liquids and the errors associated with processing the samples are additional concerns with using composite samplers.
Accordingly, the use of on-line real time analyzers such as capacitance, RF (i.e., radio frequency), and microwave analyzers to measure the water content of petroleum products is becoming more common. Real time data can provide several beneficial operational advantages. Knowledge of when water becomes present in petroleum as it is being produced and the magnitude of the water may provide an opportunity to remove the water before it reaches transport via pipeline or shipping tank. The real time data may show if the water is detected in several short periods of time or if it is present across the entire load of the petroleum. In addition, real time analyzers may be used as a comparison of the validity of the composite samplers.
Unfortunately, measurements such as those described above are usually subject to an uncertainty value, which is typically expressed as a standard deviation from a mean value. Knowing the uncertainty value ensures that informed decisions can be made about the data collected. An on-line water content analyzer relies on representative samples of the actual flowing stream just like a composite sampler probe. As such, the measurements of the on-line analyzer are only as good as the representative samples taken and thus may be affected by many influences. For example, the analyzer readings may be subject to random uncertainty sources such as changes in the ambient temperature. Moreover, they may also be subject to systematic uncertainty sources such as improper analyzer calibration, improper correction of the liquid temperature which can experience variations, insufficient mixing of the petroleum product due to, e.g., low flow rate, water content above the range of detection, and variations in the properties of the different crude oils present such as viscosity, emulsion, and density.
Capacitance, RF, and microwave on-line water content analyzers are particularly affected by the “wet” oil density and “dry” oil density of the petroleum. The “wet” oil density is the measured density of the oil and the water in the petroleum, whereas the “dry” oil density is the measured density of only the oil in the petroleum. The basis of the effect of the wet and dry oil densities is that such on-line analyzers detect changes in the polar moment of a molecule, which affects the electrical properties of permittivity and thus the dielectric constant, i.e., the normalized real part of permittivity. Those on-line analyzers are more sensitive to the water molecule because the parameter of measurement is the large difference between the small polar moment of crude oils (dielectric constant ranges from 2 to 2.5) and the high polar moment of water (dielectric constant ranges from 68-80).
The density of a petroleum product is therefore relational to the dielectric constant. This relationship is illustrated in FIG. 9, which shows that the dielectric constant decreases as the wet oil density of the petroleum, i.e., the American Petroleum Institute (API) gravity, increases. The dielectric constant also decreases as the dry oil density of the petroleum increases. It is therefore desirable to develop methods for correcting the on-line water content analyzer measurements for wet and dry oil densities.
Water Cut Measurement with Improved Correction for Density
The present application describes systems and methods for measuring the water fraction (“water cut”) in a stream of crude oil. A measurement of physical density is used to supply a correction factor for the electrical on-line characterization of water cut, but the correction factor is capped to that for a modest water fraction, e.g. 5%. This ensures that corrected measurements are achieved at low densities as before, while avoiding error due to overcorrection at higher water fractions.
The disclosed innovations, in various embodiments, provide one or more of at least the following advantages:
More accurate measurements at high water cuts;
Accurate measurements at low water cuts;
Simple implementation.